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Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited
2007. All rights reserved. i
BUNNYTHORPE-WILTON (JUDGEFORD TO WILTON SECTION) RECONDUCTORING INVESTIGATION
CONSULTATION ON PREFERRED REPLACEMENT OPTION AND
APPLICATION OF THE INVESTMENT TEST
Transpower New Zealand Limited
March 2018
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
2
Table of Contents
Glossary ...................................................................................................................... 4
Executive Summary .................................................................................................... 6
The purpose of this document ..................................................................................... 6
The need for investigation ........................................................................................... 6
Option assessment ..................................................................................................... 6
Application to the Commerce Commission .................................................................. 8
1 Option Assessment Approach ........................................................................ 10
2 Need verification and assessment level .......................................................... 11
2.1 Background ................................................................................................. 11
2.2 Need ........................................................................................................... 13
2.2.1 Asset condition ..................................................................................... 13
2.2.2 Safety................................................................................................... 15
2.2.3 Criticality .............................................................................................. 15
2.3 Determine assessment level ....................................................................... 16
3 Identify options ............................................................................................... 17
4 Assess options ............................................................................................... 20
4.1 The short-list ............................................................................................... 20
4.2 The Base Case option ................................................................................. 21
4.3 Costs ........................................................................................................... 21
4.3.1 Capital expenditure .............................................................................. 21
4.3.2 Operating expenditure .......................................................................... 22
4.3.3 Total present value costs ..................................................................... 23
4.4 Economic assumptions ............................................................................... 23
4.5 Benefits ....................................................................................................... 23
4.5.1 System dispatch benefits: .................................................................... 23
4.5.2 Reliability benefits: ............................................................................... 24
4.5.3 Loss benefits ........................................................................................ 25
4.5.4 Expected net electricity market benefit ................................................. 27
4.5.5 Robustness of the results ..................................................................... 28
4.6 Unquantified benefits: ................................................................................. 28
5 Identify solution ............................................................................................... 31
6 Consultation to date ........................................................................................ 32
1 Option Assessment Approach
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited.
All rights reserved. 3
7 Application to the Commerce Commission ..................................................... 32
7.1 Draft proposal ............................................................................................. 34
7.2 Pricing implications ..................................................................................... 35
8 Feedback requested ....................................................................................... 37
A.1 Capex IM requirements .................................................................................. 38
A.2 Short-listed conductors ................................................................................... 39
A.3 September 2016 stakeholder consultation: summary of submissions with
Transpower responses .............................................................................................. 40
A.4 Consultation questions in this document ......................................................... 44
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
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Glossary
AAAC All aluminium alloy conductor
ACOT Avoided cost of transmission
ACSR Aluminium conductor steel reinforced
AoB Area of benefit
Authority Electricity Authority
Blow-out allowance
Wire reference wind deflection limit
Capex IM Capital Expenditure Input Methodology Determination, New Zealand Commerce Commission1
Code Electricity Industry Participation Code 2010
DGPP Distributed generation pricing principles
EDGS Electricity Demand and Generation Scenarios
GDP Gross domestic product
GSC Grid support contract, used for non-transmission solutions
GUP Grid upgrade plan
GXP Grid exit point
Long-list consultation
Transpower’s consultation document titled Bunnythorpe-Wilton (JFD-WIL) Reconductoring, Long-list Consultation
LRMC Long run marginal cost
MBIE Ministry of Business, Innovation and Employment
MWh Megawatt hour of electrical energy
N-1 A security standard described that maintains the supply of electricity following a contingent event (e.g. a circuit outage).
Present Value
Future costs discounted to a present value using an assumed discount rate.
Rankine A type of coal/gas plant owned and operated by Genesis Energy at Huntly
RCPD Regional coincident peak demand (of the TPM)
RFP Request for proposal
1 See http://www.comcom.govt.nz/regulated-industries/electricity/electricity-transmission/
1 Option Assessment Approach
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited.
All rights reserved. 5
SDDP Stochastic Dual Dynamic Programming – a market dispatch model used to determine the optimal dispatch of hydro, thermal and other renewable generation.
TPM Transmission pricing methodology, defined in Schedule 12.4 of the Code
Transpower Transpower New Zealand Limited, owner and operator of New Zealand’s high-voltage electricity network (the national grid)
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
6
Executive Summary
The purpose of this document
We are consulting on our preferred solution for reconductoring the Judgeford to Wilton
section of the Bunnythorpe to Wilton A line, and our cost-benefit analysis used to
determine the preferred solution. Our preferred option is to replace the existing Zebra
conductor with a new simplex Chukar conductor and reconfigure both circuits at the
Judgeford deviation to create a ‘double tee’ connection. It has an approximate cost of
$44 million. Subject to feedback from this consultation, we intend to apply to the
Commerce Commission to increase our Regulatory Control Period 2 funding baseline
to account for the portion of this work that we expect to commission before 1 July
2020.
The need for investigation
The Bunnythorpe to Wilton A line consists of two circuits that supply Central
Wellington load via the Wilton substation and provide interconnection to transport
South Island generation to load in the North Island. Under typical conditions, energy
travels from the northern end of the HVDC link at Haywards to Wilton on the
Haywards-Wilton-1 circuit and from Wilton to Bunnythorpe in the Central North Island
on the Bunnythorpe-Wilton-1 circuit.
Conductor condition assessment has shown that the Judgeford to Wilton section of
the line has reached end-of-life and requires replacement within the next 3-4 years. If
a conductor failed due to its poor condition, it is likely to fall onto the ground,
potentially causing damage to property below and creating a significant safety risk.
The crossing over the State Highway 1 Johnsonville to Porirua motorway and the
electrified North Island Main Trunk Railway at span 314A poses a considerable safety
risk. A conductor failure would also cause an unplanned outage, potentially
constraining generation dispatch until repairs could be undertaken. While not usually
resulting in a loss of supply2, an outage3 would reduce transmission capacity between
Haywards and Bunnythorpe to a level that could constrain South Island generation in
order to maintain N-1 transmission security. This could result in increased generation
cost to consumers in the North Island. Repairs may take some time as the terrain
between Wilton and Judgeford is difficult. We believe it is prudent to replace this
section of conductor as soon as possible.
Option assessment
We considered a variety of options to address the condition of the existing conductor.
Our preferred solution is to reconductor the Judgeford to Wilton section with Chukar
2 If a conductor failed where the Bunnythorpe–Wilton line crosses the HVDC line, both HVDC poles would
trip. At medium to high HVDC transfer this would cause a widespread loss of supply due to Automatic
Under Frequency Load Shedding (AUFLS).
3 In this context an “outage” refers to a circuit being out of service. It does not necessarily mean there will
be a power outage. We use the term “interruption” to refer to power outages e.g. an interruption to our
service.
1 Option Assessment Approach
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited.
All rights reserved. 7
conductor in a simplex configuration with a new ‘double tee’ connection at Judgeford
(the rest of the line will remain duplex Zebra). The upfront costs for this option are
similar to a like-for-like replacement as the savings in reconductoring are offset by
increases in protection, substation and SPS modification costs. However, there are
significant loss benefits associated with the double tee configuration that give it the
highest net benefit. Options 2-7 all have a significant reliability benefit over
dismantling the line, as a dismantling option would materially reduce reliability in the
Wellington region. Our analysis is illustrated in Table 1 below.
Table 1 Cost-benefit analysis of options, 2017 dollars
Option 1 Dismantle WIL-JFD section
Option 2 Duplex Zebra @65°C
Option 3 Duplex Zebra @75°C
Option 4 Duplex Goat @94°C
Option 5 Duplex Selenium @70°C
Option 6 Duplex Sulphur @57°C
Option 7 Double Tee Simplex Chukar @65°C
Capital Cost $ - $ 33.1m $ 33.1m $ 31.2m $ 33.0m $ 34.0m $ 34.2m
Operating Cost $ 8.2m $ 7.6m $ 7.6m $ 7.6m $ 7.6m $ 7.6m $ 7.6m
Total Cost $ 8.2m $ 40.7m $ 40.7m $ 38.8m $ 40.6m $ 41.6m $ 41.8m
Loss Benefit $ - $ 0.8m $ 0.8m -$ 0.9m $ 1.4m $ 2.7m $ 6.2m
Reliability Benefit $ - $ 75.9m $ 75.9m $ 75.9m $ 75.9m $ 75.9m $ 75.9m
Total Benefit $ - $ 76.7m $ 76.7m $ 75.0m $ 77.3m $ 78.6m $ 82.0m
Net Benefit -$ 8.2m $ 36.0m $ 36.0m $ 36.2m $ 36.7m $ 37.0m $ 40.2m
Due to the similarity4 in net benefit of Options 5, 6, and 7, an assessment of
unquantified benefits was performed as required by the Investment Test defined in the
Capex IM. The unquantified benefits considered included electrical field and audible
noise, conductor blow-out allowance, certainty around construction and maintenance
costs and option value.
The unquantified assessment further strengthened the case for Option 7 over Option 5
or Option 6. There is little difference in unquantified benefits other than some
potentially significant issues with Options 5 and 6 related to the AAAC conductors.
Therefore, we consider Option 7 – a double tee at Judgeford and reconductoring the
Judgeford to Wilton section with simplex Chukar – to be the preferred solution.
4 Two options are considered similar in the Capex IM if the difference in net benefit is less than 10% of
the total project cost of the option with the highest net benefit.
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
8
Application to the Commerce Commission
This reconductoring project was identified as a “listed project” in the Commerce
Commission’s Transpower Individual Price Quality Determination 20155. As a listed
project, we are required to apply to the Commission for an increase to our capex
funding baseline6 to recover the costs of this project.
The primary driver for this work is the condition of the conductor between Judgeford
and Wilton. Despite our preferred option not being a like-for-like replacement, the
service potential of these assets will not be increased under the preferred option.
That means the preferred option is a base capex project and a listed project, not a
major capex project. The preferred option also provides a small increase in network
capacity due to a reconfiguration that allows us to reduce the capacity of the
Judgeford-Wilton section. However, this increase in network capacity is a side-benefit
of the preferred option and does not drive the economics, which are based on capital
costs and loss benefits.
We expect the cost of the reconductoring and reconfiguration of the Judgeford to
Wilton section of the Bunnythorpe to Wilton line will be $44m including interest during
construction and inflation. We are still refining our estimate of the total cost of this
work and the volume of work that can be completed in this regulatory period before
our application to the Commerce Commission.
However, we only expect to commission $8.9m in our current regulatory period so we
intend to apply for an increase in our funding baseline of $8.9m in our current
regulatory period (referred to as Regulatory Control Period 2, RCP2). The remainder
of the cost will be recovered through Base Capex in RCP3. Table 2 shows how we
arrived at our $8.9m estimate. We are currently undertaking further work to refine this
cost and will apply to the Commerce Commission to recover the confirmed cost.
We are targeting making our application in June 2018. Unless the confirmed cost is
significantly different (more than 30% greater) we do not intend to consult further on
this project before making an application.
5 http://www.comcom.govt.nz/dmsdocument/14912
6 We use the term ‘funding baselines’ to refer to base capex allowances. This terminology better reflects
the operation of our regulatory arrangements (i.e. the allowances are incentive baselines rather than
limits).
1 Option Assessment Approach
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Table 2 Listed project capital allowance application
Cost distribution
Range of distribution
Point selected within distribution (probability)
Cost applied for ($000)
Capex (real 2017$) Triangle +30% / -30% P50 8,675
Inflation 190
Exchange rates -
IDC 30
Total LPCA (2020$) 8,894
Proposal at a Glance
What: Replace the existing conductors on the Judgeford to Wilton section of the Bunnythorpe to Wilton line with simplex Chukar, and reconfiguration to a ‘double tee’ connection at Judgeford.
When: Commence work in Q4 2019 and complete by Q4 2021
How much: Transpower is seeking approval to add $8.9 million to our base capex funding baseline for RCP2 to reflect the cost of assets commissioned before 1 July 2020. The remaining cost will be included as base capex in our RCP3 funding application.
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
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1 Option Assessment Approach
Below we outline how we have arrived at our preferred option and the options and
process that we used. We have followed our internal Option Assessment Approach.
This involves four key stages of investigation designed to systematically identify the
best option, as illustrated below:
Figure 1 Option Assessment Approach Stages
Verify Need and Determine Assessment level – This step focuses on confirming the
need for the project and determining an appropriate level of assessment given its
complexity and cost.
Identify Options – This step involves defining a long-list of potential solutions to the
identified need, and then reducing this to a short-list for further analysis. For this
project, we consulted on both the need and our long-list in September 20167 (long-list
consultation).
Assess Options – In this step we analyse the short-listed options and quantify costs
and benefits, and unquantified benefits.
Identify Solution – In this stage we identify, based on our analysis, our preferred
solution.
We outline each of these stages in relation to this project in the following sections.
7 https://www.transpower.co.nz/sites/default/files/projects/resources/Bunnythorpe-Wilton %28JFD-
WIL%29 Reconductoring Long-list Consultation_1.pdf
Verify Need and Determine
Assessment levelIdentify Options Assess Options Identify Solution
2 Need verification and assessment level
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2 Need verification and assessment level
2.1 Background
The Bunnythorpe to Wilton line (BPE-WIL A line) carries two of the four 220 kV circuits
connecting the Wellington region and Bunnythorpe. It carries two 220 kV circuits to
our Wilton substation, which is a major supply point for all of Central Wellington. The
220 kV line runs from Bunnythorpe to Wilton via Judgeford (east of Whitby).
One circuit of the BPE-WIL-A line (BPE-WIL-1) connects to Bunnythorpe via Linton
and the other (HAY-WIL-1) turns to the south-east at Judgeford to connect to
Bunnythorpe via Haywards. The 28 km section of line between Judgeford and Wilton
is in a very severe corrosive environment, particularly through the airborne salts from
the nearby coast.
The Judgeford to Wilton section of the line is indicated in orange in Figure 2 below,
with the existing network configuration shown in Figure 3.
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
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Figure 2 - Judgeford to Wilton section in the Wellington network
2 Need verification and assessment level
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited.
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Figure 3 - Existing BPE-WIL Configuration
2.2 Need
The need to replace the existing conductor is driven by three factors:
• Asset condition
• Safety
• Criticality
2.2.1 Asset condition
As we explained in our long-list consultation, inspection and testing to date has
identified a number of conductor defects approaching Transpower replacement criteria
and general conductor degradation, which indicates that accelerated corrosion is likely
to be occurring on many spans in this line section.
Recent conductor condition assessment has shown that this section of the line has
now reached replacement criteria and requires replacement within the next 3-4 years,
with localised corrosion defects already exceeding replacement criteria. The severity
and number of defects found on this line section is such that continuing to manage
issues with inspection and corrective maintenance will not adequately address the risk
of conductor failure.
The photographs below show corrosion of the Bunnythorpe to Wilton A conductor and
degradation of the ACSR conductor.
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
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Figure 4: Example of corrosion bulge close to repair sleeve (since repaired)
Figure 5 - Dismantling of conductor bulges in 2011
2 Need verification and assessment level
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On-going repairs and inspections will be required to ensure the risk of a conductor
failure is appropriately managed until the Zebra conductor is replaced. This is likely to
be in the form of conductor defect removal and regular close aerial inspections.
Patching is not a practical long-term solution as the conductor condition worsens and
repair costs increase. Additionally, the large number of deteriorated sections pose a
risk of conductor drop that is too high for safety and system security. Conductor repair
is very difficult and costly due to the terrain traversed by sections of this line, thus
poses additional risks when handling defective conductor.
Other more northern sections of the line however are installed in less corrosive
environments and are not expected to require replacement until between 2020 and
2030. Further work will be undertaken as part of a separate investigation closer to the
need date.
2.2.2 Safety
As the conductor continues to deteriorate, our ability to effectively maintain it will
reduce over time, to a point where it is no longer safe or cost effective to do so.
Conductor deterioration will ultimately reduce contractor safety during future
reconductoring activities. If no action is taken, this ongoing deterioration will increase
the risk of conductor failure.
If a conductor failed due to poor condition, it is likely to fall onto the ground below.
Potential consequences associated with such an event include fire to vegetation and
property, electrocution, or harm from physical impact. Most of the line section passes
over reserve or farmland with no spans passing particularly near to urban areas
except at Wilton. The crossing over the State Highway 1 Johnsonville to Porirua
motorway and the electrified North Island Main Trunk Railway at span 314A poses a
potential safety risk in the event of a conductor drop. There are also several instances
where the Bunnythorpe–Wilton A line crosses over other transmission assets, which
would create additional safety risk and system consequences following a conductor
drop. While the likelihood of failure is low at present, it will increase over time.
2.2.3 Criticality
The BPE-WIL A line consists of two 694/762 MVA (summer/winter) circuits that supply
Central Wellington load via the Wilton substation and provides interconnection to
transport South Island generation to load in the North Island. Under typical conditions,
energy travels from the northern end of the HVDC link at Haywards to Wilton on the
HAY-WIL-1 circuit and from Wilton to Bunnythorpe in the Central North Island on the
BPE-WIL-1 circuit.
An unplanned outage on one circuit would not result in loss of supply but could
constrain generation dispatch until repairs could be undertaken. Following an outage,
transmission capacity between Haywards and Bunnythorpe would be reduced to a
level that could constrain South Island generation in order to maintain N-1
transmission security. This could result in increased generation cost to consumers in
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
16
the North Island. Repairs could take some time as the terrain between Wilton and
Judgeford is difficult.
Permanent removal of the Judgeford to Wilton section of both circuits would leave all
Central Wellington load supplied only from the two 110 kV circuits from Takapu Road
to Wilton. This reduction in security to a large residential load (approximately
250 MW) and the increased loss cost was considered in this investigation and found
to be uneconomic.
2.3 Determine assessment level
We have undertaken a detailed investigation and modelling of generation dispatch
costs because:
• the need to replace the conductor is imminent;
• the conductor is part of a critical piece of equipment;
• the cost of investment is significant; and
• regulatory approval is required for this project.
Question 1: Are there any other considerations relating to the need that we
should incorporate into this project?
3 Identify options
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3 Identify options
In September 2016 we consulted on a draft long-list of options in our long-list
consultation. We have subsequently confirmed the long-list of options and reduced
the long-list to a short-list using the following short-listing criteria that we also
consulted on:
1. Fit for purpose 2. Technical feasibility 3. Practicability of implementing the option 4. Good electricity industry practice (GEIP) 5. System security (additional benefit resulting from an economic investment) 6. Indicative cost
The following table outlines our long-list options and our assessment of whether an
option is shortlisted. Options considered in the short-list are marked with a ✓. This
indicates the option forms part of a short-listed plan. It may not be the entire plan in
the short-list, i.e. a long-list option being short-listed does not mean it can by itself
completely resolve the need.
Table 3 Long-list Assessment
Longlist options Short-list?
Comments
Non-transmission options: Demand side
Load shedding SPS – post contingency
Fails criterion 1 – not fit for purpose. This component does not address the poor condition of the assets and does not present an entire solution. However, this could be used to defer investment in combination with other long-list components.
Load shifting Fails criterion 1 – not fit for purpose. As above
Demand Side Response (DSR) – pre contingency
Fails criterion 1 – not fit for purpose. As above
Non-transmission options: Supply side
New generation Fails criterion 1 – not fit for purpose. There is no indication from industry this is imminent. A range of generation scenarios will be considered in the options assessment.
Generation re-dispatch
Fails criterion 1 – not fit for purpose. This component does not address the poor condition of the assets and does not present an entire solution. This component is implicitly included in the short-list as it is covered in the Stochastic Dual Dynamic Programming (SDDP) analysis.
New distributed generation
Fails criterion 1 – not fit for purpose. There is no indication from industry this is imminent. A range of generation scenarios will be considered in the options assessment.
Transmission options - new assets: New circuit
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Longlist options Short-list?
Comments
New double circuit line
Fails criterion 1 – not fit for purpose. There is considerable spare capacity on the existing line so doubling circuit is not necessary.
New underground cable
Fails Criterion 6 – indicative cost. Undergrounding a large line through poor terrain will be prohibitively expensive.
Transmission options - new assets: New switching station
New switching station
Fails Criterion 1 – not fit for purpose. Does not address the poor condition of the assets.
Transmission options - new assets: New grid exit point
New grid exit point Fails Criterion 1 – not fit for purpose. Does not address the poor condition of the assets.
Transmission options – existing assets: Grid reconfiguration
Double tee connection
Short-listed. The Judgeford double tee option converts the loop-in, loop-out connection to Haywards and Wilton into a double tee at Judgeford.
HVDC runback This component does not address the poor condition of the assets and does not present an entire solution. This component is implicitly included in all development plans.
Transmission options – existing assets: Reconductor Judgeford-Wilton
Keep exiting rating Short-listed
Increase circuit ratings
Fails criterion 1 – not fit for purpose. The circuit is currently under-utilised so additional capacity is not required.
Simplex: lower rated circuits
Fails criterion 1 – not fit for purpose. Configuring a Simplex circuit over the length of line involved will result in prohibitively high impedance. However, Simplex may be utilised in small sections of the line.
Duplex: lower rated circuits
Short-listed
Transmission options – existing assets: Maintain existing assets
Patch fix Fails criterion 1 – not fit for purpose. The large amount of patch fixes required means the activity will be impractical to implement and prohibitively expensive. This could be used to defer investment in combination with other long-list components.
Dismantling Judgeford-Wilton
Short-listed
If we were to dismantle the JFD-WIL section of the line, load at WIL, CPK, KWA, TKR, and PNI would be supplied solely from the 110 kV double-circuit HAY-TKR-WIL line. A double circuit outage (planned or unplanned) would mean that any load at these GXPs could not be supplied. This option is short-listed to provide a reference point from which system benefits for other options are relative.
3 Identify options
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Question 2: Do you agree with our assessment of the long-list?
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4 Assess options
4.1 The short-list
Options 3 – 6 in the table below explore different conductor technologies and sizes
while maintaining the same rating as the existing design. Different conductor sizes
were selected to compare the wind loadings, operating temperatures, and the cost of
structure and clearance modifications required.
Option 2 is like-for-like conductor with a reduced rating to investigate possible cost
savings.
Option 1 is significantly different in that it requires the dismantling of the existing circuit
(and continuing power system operations in its absence permanently).
Option 7 is significantly different again as it changes the circuits to a double tee
connection, improving the distribution of power across the circuits. This option would
utilise a simplex conductor configuration as opposed to the existing duplex conductor
configuration.
Table 4 Short-list of options
Option
#
Option Description
1 Dismantling JFD-WIL and create a 2nd BPE-LTN-HAY circuit
• Remove JFD-WIL section of circuits and jumper across at Judgeford
2 Duplex Zebra ACSR Option A - Reduced rating
• Replace assets with modern equivalent of the existing Duplex Zebra ACSR/AC
• 65°C (reduced rating)
3 Duplex Zebra ACSR Option B - Existing rating
• Replace assets with modern equivalent of the existing Duplex Zebra ACSR/AC
• 75°C (existing rating)
4 Duplex Goat ACSR Existing rating
• Replace assets with Duplex Goat ACSR/AC
• 94°C ( existing rating)
5 Duplex Selenium AAAC Existing rating
• Replace assets with Duplex Selenium AAAC
• 70°C (existing rating)
6 Duplex Sulphur AAAC Existing rating
• Replace assets with Duplex Sulphur AAAC
• 57°C (existing rating)
7 Double tee connection • Reconfigure circuits at the Judgeford deviation to create a ‘double tee’ connection at Judgeford and reconductor the JFD-WIL section with simplex Chukar. See Figure 6 below.
4 Assess options
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited.
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Figure 6 - Option 7: Double tee
4.2 The base case option
Dismantling of the Judgeford to Wilton section (Option 1) is our base case option.
This option provides a basis to justify retaining the section of line, and is a reference
point for relative system benefits of each of the other short-listed options.
4.3 Costs
4.3.1 Capital expenditure
In our analysis of the short-list we have included both capital and operational costs.
Our capital costs were derived from a high-level desk top study, with an uncertainty
range of -50%/+50% for lines-related costs. The capital costs include:
• investigation and design;
• materials (conductors, insulators & hardware);
• construction (conductors, structures, foundations, access and property); and
• protection systems (duplicate line protection, SPS and runback
modifications).
For Option 1, there is little capital expenditure as no new assets are required, and
dismantling costs fall under operating expenditure.
For Options 2 - 6, the primary cost difference occurs in conductor materials, with other
cost differences in structure and foundation strengthening. Option 7 requires a new
Bunnythorpe-Wilton (Judgeford to Wilton Section) Reconductoring Investigation © Transpower New Zealand Limited. All rights reserved.
22
220 kV bay at Linton and protection upgrades at several substations and these costs
are included.
In Table 5 the capital cost differences between options are related to the conductor
material, clearance rectification and structural / foundation works required. We
consider that this approach reasonably assesses the cost differences between
options.
Table 5 Capital costs (real 2017, 000’s)
Capex, $,000’s Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Reconductoring, foundation and tower strengthening, and protection work
N/A 40,500 40,500 38,200 40,400 41,600 41,900
P50 capex N/A 40,500 40,500 38,200 40,400 41,600 41,900
4.3.2 Operating expenditure
We have assumed operating costs of $650k per annum, which includes all expected
maintenance spend on this section of the line. We don’t expect there to be any
material differences in the operating costs across the short-list options that retain the
JFD-WIL section of the line.
4 Assess options
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4.3.3 Total present value costs
The following table summarises the capital and operating costs in nominal terms, and
also shows the total present value (PV) of these costs.
Table 6 Cost of Options $000 (2017 $ excluding IDC)
$,000’s Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Capital cost N/A 40,500 40,500 38,200 40,400 41,600 41,900
Annual opex (over life of asset)
0 650 650 650 650 650 650
Dismantling cost 10,700 N/A N/A N/A N/A N/A N/A
Total present value (PV) cost $ 8,200 $ 40,700 $ 40,700 $ 38,800 $ 40,600 $ 41,600 $ 41,800
4.4 Economic assumptions
The assumptions used in this analysis are consistent with our long-list consultation:
• We used a 7% pre-tax real discount rate as outlined in the Capex IM.
• Value of Lost Load (VoLL): $25,300/MWh based on the Code8-defined as
$20k/MWh in 2004 and inflated at CPI to 2017 dollars.
• We used a 40 year analysis period (2020-2060) for valuing losses, given the
long life of the asset.
• Our generation plant assumptions are consistent with MBIE’s Electricity
Demand and Generation Scenarios (EDGS).
• Our energy demand forecast is based on Transpower’s 2016 Transmission
Planning Report (TPR). The demand forecast also incorporates electric
vehicle and solar photovoltaic uptake assumptions which are consistent with
MBIE’s EDGS.
• We assumed that replacement of the conductor takes place in in 2020.
4.5 Benefits
4.5.1 System dispatch benefits
All short-list options being considered provide enough capacity to meet the expected
grid flows without constraining dispatch. Therefore, no significant difference in
dispatch costs exists between the options. Option 1 dismantles the JFD-WIL section
but retains the remainder of the BPE-WIL line, so it also realises the same dispatch
and deficit benefits as the other options.
8 Electricity Industry Participation Code
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24
4.5.2 Reliability benefits
We considered the reliability benefits of retaining a 220 kV connection to Wilton to
compare dismantling the JFD-WIL section of BPE-WIL with the other short-listed
options.
If we were to dismantle the JFD-WIL section of the line, load at Wilton, Central Park,
Kaiwharawhara, Takapu Road, and Pauahatanui would be supplied solely from the
110 kV double-circuit HAY-TKR-WIL line. A double circuit outage (planned or
unplanned) would result in a loss of supply to these GXPs (much of Wellington City
load).
The HAY-TKR and TKR-WIL circuits are strung on double circuit towers meaning that
outages of the two circuits cannot be treated as independent. Planned and unplanned
outages are both more likely to impact both circuits when they are on a single tower.
Inspection of historical outages of these lines found that 28% of outages were double-
circuit outages.
We expect that generation connected in the affected area (West Wind and Mill Creek)
would not remain connected following a double circuit outage.
As all short-list options (except the base case dismantle option) provide a second
distinct connection into Wilton, they share the same reliability benefits to supply
Wellington City.
4 Assess options
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4.5.3 Loss benefits
There are differences in the losses from each of the conductors. Larger conductors
that run at lower temperatures will result in lower electrical losses.
Loss benefits were modelled using SDDP9, a hydrothermal dispatch optimisation
package. SDDP considers the future value of water to the electricity system to
establish a water-value function then simulates least-cost dispatch across 78 historic
hydro inflow sequences.
We considered five market development scenarios (GS 1-5) based on the Ministry of
Business, Innovation and Employment’s (MBIE’s) draft Electricity Demand and
Generation Scenarios (EDGS)10. Use of market development scenarios enables us to
capture a range of possible future states of the electricity system to ensure the
economic test is robust. All fuel, carbon, and variable plant costs are as defined in the
draft EDGS as are plant specifications.
The EDGS scenarios are:
• Mixed Renewables: a mixture of geothermal and wind plant is built to meet an
average of 1% annual electricity load growth. This scenario reflects moderate
GDP, population, carbon and fuel cost, and technology uptake assumptions.
• High Grid: higher GDP growth results in 1.3% annual electricity load growth
and higher levels of gas exploration results in more gas availability.
• Global Low Carbon: higher carbon price leads to more grid-connected
renewable build and higher uptake of petrol-electric hybrid vehicles and
residential solar PV. Energy efficiency measures also result in flat electricity
demand per household.
• Disruptive: reduced technology costs result in rapid uptake of residential and
commercial solar PV and pure electric vehicles. Batteries facilitate load-
shifting resulting in a less peaky daily load profile.
• Tiwai Off: Tiwai shuts at the start of 2018 resulting in the retirement of more
thermal generation. Lower GDP growth results in lower annual electricity load
growth of 0.4%.
The scenarios presented in the EDGS were modified to reflect updated demand
forecasts and ensure that there is adequate diversity with respect to the investment
being considered. To that end, we have ensured that there is diversity in the
commissioning of new generation in the Wellington region.
9 Stochastic Dual Dynamic Programming
10 http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-data-
modelling/modelling/electricity-demand-and-generation-scenarios/draft-edgs-2015
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26
The table below presents the expansion of generation in the Wellington region in each
scenario.
Table 7 Generation expansion in Wellington region by scenario
Mixed Renewables
High grid Global low Carbon
Disruptive Tiwai Off
2020
Turitea (183 MW)
2021
2022 Turitea (183 MW)
Turitea (183 MW)
2023
GWindS1 (68 MW)
GWindS1 (68 MW)
2024
Castle Hill stage 1 (200 MW)
2025 GWindS1 (68 MW)
Castle Hill stage 2 (200 MW)
Castle Hill stage 1 (200 MW)
2026
Castle Hill stage 3 (200 MW)
Castle Hill stage 2 (200 MW)
2027 Castle Hill stage 1 (200 MW)
Puketoi (159 MW)
Turitea (183 MW)
2028
2029
Turitea (183 MW)
2030
GWindL1_stage 1 (250 MW)
2031
2032
2033
GWindL1_stage 2 (250 MW)
2034 GWindL1_stage 1 (250 MW)
GWindL1_stage 1 (250 MW)
2035
2036
GWindL1_stage 1 (250 MW)
2037
2038
GWindL1_stage 2 (250 MW)
GWindL1_stage 2 (250 MW)
2039
GWindS1 (68 MW)
2040
2041
2042
2043
GWindL1_stage 1 (250 MW)
2044 GWindL1_stage 2 (250 MW)
Castle Hill stage 1 (200 MW)
2045
Castle Hill stage 2 (200 MW)
Puketoi (159 MW)
2046
Puketoi (159 MW)
2047
GWindL1_stage 2 (250 MW)
2048
2049 Puketoi (159 MW)
GWindS1 (68 MW)
2050
4 Assess options
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The table below shows the relative loss benefit between options (when averaged
across the five EDGS scenarios), using a 7% pa discount rate. The expected life of
the asset was assumed to be 40 years for valuing the losses.
Table 8 Loss benefits relative to Option 1 - 2021-2060 (PV 2017 dollars)
Option # Option Relative Loss Benefit
1 Dismantling JFD-WIL $ 0
2 Duplex Zebra A Reduced circuit rating
$ 0.8m
3 Duplex Zebra B Existing circuit rating
$ 0.8m
4 Duplex Goat -$ 0.9m
5 Duplex Selenium $ 1.4m
6 Duplex Sulphur $ 2.7m
7 Double tee $ 6.2m
4.5.4 Expected net electricity market benefit
Table 9 shows the net market benefits for each short-list option. This quantified
assessment shows that the double tee connection option has the highest net benefit
given the total cost of the project. This is due to a decrease in losses relative to the
Options 2 – 6 as the reconfigured circuit provides a shorter path for energy flowing
between Haywards and Bunnythorpe.
The AAAC conductor options – Sulphur and Selenium – have the second and third
highest net benefit by a small margin given the total cost of the project. The benefit of
the AAAC conductor is due to a decrease in losses relative to the ACSR options.
Given the similarity in the quantified differences between the conductor options, we
consider unquantified benefits should be considered when selecting the preferred
solution. Unquantified benefits are discussed in later in this document.
Table 9 Net benefit test (PV 2017 dollars) – all benefits relative to Option 1
Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Capital Cost $ - $ 33.1m $ 33.1m $ 31.2m $ 33.0m $ 34.0m $ 34.2m
Operating Cost $ 8.2m $ 7.6m $ 7.6m $ 7.6m $ 7.6m $ 7.6m $ 7.6m
Total Cost $ 8.2m $ 40.7m $ 40.7m $ 38.8m $ 40.6m $ 41.6m $ 41.8m
Loss Benefit $ - $ 0.8m $ 0.8m -$ 0.9m $ 1.4m $ 2.7m $ 6.2m
Reliability Benefit $ - $ 75.9m $ 75.9m $ 75.9m $ 75.9m $ 75.9m $ 75.9m
Total Benefit $ - $ 76.7m $ 76.7m $ 75.0m $ 77.3m $ 78.6m $ 82.0m
Net Benefit -$ 8.2m $ 36.0m $ 36.0m $ 36.2m $ 36.7m $ 37.0m $ 40.2m
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28
4.5.5 Robustness of the results
We undertook sensitivity analysis to determine the robustness of our quantified option
assessment. The below table shows the net benefit / (cost) relative to our base case
(dismantle). It shows the difference in the present values of each option under low
and high sensitivities:
• Costs: -30% / +30%
• Losses: -25% / +25%
• Discount rate: +4% / + 10%
• Reliability: +25%
• VoLL: -50% / +50%
Each row shows the impact from changing only that single cost driver.
Table 10 Sensitivity analysis - Net Benefit (PV 2017 dollars)
Option 1 Dismantle WIL-JFD section
Option 2 Duplex Zebra @65°C
Option 3 Duplex Zebra @75°C
Option 4 Duplex Goat
@94°C
Option 5 Duplex
Selenium @70°C
Option 6 Duplex Sulphur @57°C
Option 7 Double Tee
Simplex Chukar @65°C
Base scenario
-$ 8.2m $ 36.0m $ 36.0m $ 36.2m $ 36.7m $ 37.0m $ 40.2m
Discount Rate 4%
-$ 9.1m $ 83.1m $ 83.1m $ 82.3m $ 84.1m $ 85.0m $ 91.4m
Discount Rate 10%
-$ 7.3m $ 13.6m $ 13.6m $ 14.2m $ 14.1m $ 14.0m $ 15.8m
Capital Cost - 30%
-$ 8.2m $ 46.0m $ 46.0m $ 45.5m $ 46.6m $ 47.2m $ 50.5m
Capital Cost + 30%
-$ 8.2m $ 26.1m $ 26.1m $ 26.8m $ 26.8m $ 26.8m $ 29.9m
Loss Benefit -25 %
-$ 8.2m $ 39.1m $ 39.1m $ 39.6m $ 39.6m $ 39.5m $ 41.9m
Loss Benefit + 25 %
-$ 8.2m $ 36.2m $ 36.2m $ 35.9m $ 37.1m $ 37.7m $ 41.7m
Reliability + 25%
-$ 8.2m $ 17.1m $ 17.1m $ 17.2m $ 17.8m $ 18.0m $ 21.2m
VoLL -50%
-$ 8.2m -$ 1.9m -$ 1.9m -$ 1.8m -$ 1.2m -$ 0.9m $ 2.3m
VoLL +50%
-$ 8.2m $ 74.0m $ 74.0m $ 74.1m $ 74.7m $ 74.9m $ 78.1m
Option 7 remains has the highest net benefit in all sensitivity cases. Therefore, we
consider this result robust to sensitivity analysis.
4.6 Unquantified benefits
We have further assessed the suitability of the short-list options against each other
using a variety of other considerations. To do this we have used a tick box analysis,
with options with three ticks seen as providing a high level of benefit. This is shown in
the table below.
4 Assess options
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The primary purpose of the unquantified assessment is to determine whether there
are material unquantified benefits associated with options that have similar net
benefits to the option with the highest net benefit – Option 7 in the previous section.
The Investment Test defines two options as similar if the difference in quantified net
electricity market benefit is less than 10% of the capital cost for the option with the
highest net benefit - $4m in this case. So, Options 5 and 6 are similar to Option 7.
Therefore, the unquantified benefits assessment below should be considered in the
context of the options that are similar – shown in bold below. Unquantified benefits
associated with options that are not similar in the quantified assessment are included
for context but do not affect the preferred option.
There are two significant outcomes from our unquantified assessment:
1. There is very little difference in unquantified benefits between any of the short-
listed options.
2. Option 7 – Double Tee – is preferred to the similar options (Options 5 and 6) in
unquantified terms.
Table 11 Unquantified assessment of benefits
Item
Op
tio
n 1
Dis
man
tle
WIL
-JFD
sect
ion
O
pti
on
2
Du
ple
x Ze
bra
@6
5°C
Op
tio
n 3
Du
ple
x Ze
bra
@7
5°C
Op
tio
n 4
Du
ple
x G
oat
@9
4°C
Op
tio
n 5
Du
ple
x
Sele
niu
m@
7
0°C
O
pti
on
6
Du
ple
x
Sulp
hu
r
@5
7°C
O
pti
on
7
Do
ub
le T
ee
Electrical field and audible noise
✓✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓✓ ✓✓✓
Conductor blow-out allowance ✓✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓ ✓✓ ✓✓✓
Certainty construction costs ✓✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓✓ ✓✓ ✓✓
Certainty maintenance costs ✓✓✓ ✓✓ ✓✓ ✓✓ ✓✓ ✓✓ ✓✓
Option value ✓ ✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓✓✓ ✓✓
Total ticks 13 13 14 14 11 11 12
Unquantified benefits (UQB) ranking:
3= 3= 1= 1= 6= 6= 5
Electromagnetic fields and audible noise
All options are within acceptable tolerances for magnetic field, audible noise
and radio frequency interference limits. Option 6 (Duplex Sulphur) exceeds
the electrical field compliance levels in post-contingent state.
Conductor blow-out allowance
Blow-out allowance, containing the conductor within the same width of a
reference position (e.g. when blown in the wind), is a factor when considering
alternative conductor options. The magnitude of blow-out magnitude
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30
(conductor displacement due to wind) is a function of conductor weight
(restraining movement), conductor diameter (defining wind area) and stringing
tension (restraining conductor) which is related to conductor strength, structure
strength and vibration susceptibility.
Exceeding the blow-out allowance would require an investigation into acquiring
additional property rights from landowners.
• AAAC conductors are significantly lighter, and strung with lower
tensions than the ACSR, resulting in blow-out that exceeds the
conductor allowance.
• ACSR conductors satisfy the conductor blow-out allowance.
Certainty – Construction costs
AAAC type conductors move more in wind which increases risks during
construction (over ACSR). Work will be undertaken with one circuit live,
replacing with AAAC will significantly reduce electrical risk during construction
(over ACSR).
Certainty – Maintenance costs
All reconductoring options have similar maintenance costs. Option 1
(dismantle) has no associated maintenance costs.
Option value
Retaining the JFD-WIL section in some shape or form significantly increases
flexibility to match future build plans to needs. While the existing capacity is
not fully utilised, our analysis suggests that reducing the capacity will not
significantly reduce the cost of this project for any of the conductor options.
Options that retain the existing capacity are scored more highly for this benefit
(compared to option that reduce capacity).
Option 1 (dismantling) has the lowest option value as it entails full dismantling
and removal of the circuit. Options 2-7 all have similar option value, as they all
retain the JFD-WIL circuit. Those with higher ratings have higher option value.
Overall our assessment is that options 3 and 4 have the most unquantified benefits.
However, as all options have very similar benefits, when determining the preferred
solution, unquantified benefits have a lower weighting.
.
Question 3: Do you have any comments on our analysis of costs and
benefits for this project?
5 Identify solution
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5 Identify solution
In this stage of the Option Assessment Approach we consider both our quantified and
unquantified analysis.
As discussed above, the Investment Test, defined in the Capex IM, says that options
that have an expected net electricity market benefit within 10% of the cost of the
option with the highest net expected electricity market benefit, are considered similar,
and unquantified benefits can be considered in determining the best option. In this
case the present value of Options 5 and 6 (Selenium or Sulphur duplex respectively)
is just 8% less than the option with the highest net benefit (Option 7 – double tee).
The below table summarises the quantitative and qualitative analysis. Although
Option 7 has the highest net benefit, it has lower unquantified benefits than options 3
and 4. However, this difference in unquantified benefits is not significant enough for
these options to be preferred. We therefore consider Option 7 to have the best overall
ranking and to be our preferred solution.
Table 12 Quantitative and Qualitative ranking of options
Item
Op
tio
n 1
D
ism
antl
e
WIL
-JFD
se
ctio
n
Op
tio
n 2
Du
ple
x Ze
bra
@
65
°C
Op
tio
n 3
D
up
lex
Zeb
ra
@7
5°C
Op
tio
n 4
D
up
lex
Go
at
@9
4°C
Op
tio
n 5
Du
ple
x Se
len
ium
@
70
°C
Op
tio
n 6
D
up
lex
Sulp
hu
r @
57
°C
Op
tio
n 7
D
ou
ble
Te
e
Total cost (PV 2017 $) $ 8.2m $ 40.7m $ 40.7m $ 38.8m $ 40.6m $ 41.6m $ 41.8m
Expected Net Electricity Market Benefit (PV 2017 $) -$ 8.2m $ 36.0m $ 36.0m $ 36.2m $ 36.7m $ 37.0m $ 40.2m
Ranking based on quantified benefits (QB)
7 3= 3= 3= 3= 2 1
Ranking based on unquantified benefits (UQB):
3= 3= 1= 1= 6= 6= 5
Overall ranking QB and UQB
7 5 2 6 3 4 1
Question 4: Do you agree with our assessment of the preferred solution and
our application of the Investment Test?
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32
6 Consultation to date
In September 2016 we published our long-list consultation document11 entitled Long-
list: Bunnythorpe to Wilton line (Judgeford to Wilton section) reconductoring. In the
appendices, we provide Transpower’s responses to the feedback received from this
consultation.
The two submitters were supportive of the need for the reconductoring work to be
carried out. The first submission inquired as to the construction timeline (for
consideration in proposing a non-transmission solution) and queried inputs to the
options assessment. The second submission’s intention was “to ensure the next
phase of analysing a short-list of options and a draft application of the Investment Test
is robust.”
7 Application to the Commerce Commission
This project is a listed project within the Capex IM as stated in Transpower Individual
Price-Quality Determination 201512 for Regulatory Control Period 2 from 2015-2020
(RCP2). The listed project status means that we need to submit an application to the
Commerce Commission seeking approval to add to our base capex funding baseline13
(i.e. base capex14) to account for this work. Listed projects are large projects that had
uncertain scope and cost at the time of our RCP2 application. The listed project
mechanism was developed to allow our base capex funding baseline to be amended
when the scope and cost of these projects was more certain. We are also required to
consult on our application of the Investment Test set out in the Capex IM, which we
are fulfilling with this document.
The primary driver for this work is the condition of the conductor between Judgeford
and Wilton. Despite our preferred option not being a like-for-like replacement, the
service potential of these assets will not be increased under the preferred option.
That means the preferred option is base capex project and a listed project, not a major
capex project. The preferred option also provides a small increase in network
capacity due to a reconfiguration that allows us to reduce the capacity of the
Judgeford-Wilton section. However, this increase in network capacity is a side-benefit
of the preferred option and does not drive the economics, which are based on capital
costs and loss benefits.
11 The consultation paper, the non-confidential submissions and this document are available at
https://www.transpower.co.nz/bunnythorpe-wilton-reconductoring-investigation
12 See schedule I in http://www.comcom.govt.nz/dmsdocument/12769.
13 We use the term ‘funding baselines’ to refer to base capex allowances. This terminology better reflects
the operation of our regulatory arrangements (i.e. the allowances are incentive baselines rather than
limits).
14 Defined in the Capex IM.
7 Application to the Commerce Commission
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The Bunnythorpe to Judgeford section of the Bunnythorpe to Wilton A line is an
interconnection asset so the cost of reconductoring would be recovered from all
connected parties and allocated according to the TPM.
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34
7.1 Draft proposal
Based on our analysis we intend to develop an application to the Commerce
Commission for:
Proposal at a Glance
What: Replace the existing conductors on the Judgeford to Wilton section of the Bunnythorpe to Wilton line with simplex Chukar, and reconfiguration to a ‘double tee’ connection at Judgeford.
When: Commence work in Q4 2019 and complete by Q4 2021
How much: Transpower is seeking approval for up to $8.9m additional base capex in RCP2 to cover the cost of assets commissioned before 1 July 2020. The remainder of the project cost will be included as base capex in our RCP3 funding application
Grid Outputs Replace the existing conductors on the Judgeford to Wilton section of the Bunnythorpe to Wilton line with simplex Chukar, and reconfiguration to a ‘double tee’ connection at Judgeford, and associated works. Obtaining property rights and environmental approvals as required.
Our cost estimate for the project, while we consider appropriate for option analysis, is
currently being further refined through additional investigation. Assuming the updated
cost does not change our conclusions, we intend to make our application to the
Commerce Commission. We are targeting making an application in June 2018 and do
not intend to consult further on this project before our application.
Table 13 summarises our Listed Project Capital Allowance application of $8.9m
million. Note that this figure covers only the portion of the project commissioned in
RCP2. The remainder of the capital will be recovered through RCP3 base capex.
Table 13 Listed project capital allowance application
Cost distribution Range of
distribution Point selected within distribution (probability)
Cost applied for ($000)
Capex (real 2017$) Triangle +30% / -30% P50 8,675
Inflation 190
Exchange rates -
IDC 30
Total LPCA (2021$)
8,894
The table below provides an indicative timing of the total capital spend over the
project. We will refine these timings and include confirmed schedules in our
submission to the Commerce Commission.
7 Application to the Commerce Commission
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Table 14 List project capital allowance, annual costs
Cost by year 2018/2019 2019/2020 2020/202115
Capex (real 2017$) 868 7,808 33,260
Inflation 9 180 1,644
Exchange rates 1 28 257
IDC 878 8,016 35,160
Total LPCA (2020$) 868 7,808 33,260
7.2 Pricing implications
The costs of the preferred solution will be added to the Regulated Asset Base (RAB)
for RCP2, leading to an increase in transmission charges.
For illustrative purposes, we show in Table 15 the potential impact on transmission
charges. These transmission charge increases would be expected to reduce in time
as the asset is depreciated.
15 The cost of assets commissioned after 30 June 2020 will be recovered through base capex in RCP3
Question 5: What would you consider a material change in cost?
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36
Table 16 shows the resulting increase on an “average” consumer bill in 2028. We
define an “average” consumer as a household using 7,600 kWh per annum. The high
and low scenarios show the transmission costs if the re-conductoring capex is +/- 30%
of Option 7 (P50).
Table 15 Impact on transmission charges
Year Interconnection rate increase $/kW
Interconnection rate increase %
Consumers bill c/kWh
2019/20 0.06 0.05% 0.0009
2020/21 0.27 0.24% 0.0043
2021/22 0.46 0.41% 0.0074
2022/23 0.48 0.42% 0.0076
2023/24 0.49 0.43% 0.0078
2024/25 0.50 0.44% 0.0080
2025/26 0.51 0.45% 0.0081
2026/27 0.52 0.45% 0.0082
2027/28 0.52 0.46% 0.0083
2028/29 0.52 0.46% 0.0083
2029/2030 0.53 0.46% 0.0084
7 Application to the Commerce Commission
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Table 16 Increase in 2028 consumer cost (cents per annum)
2028 consumer bill, cents pa Base case (P50)
High (+30%)
Low (-30%)
An “average” consumer (7,600 kWh) 63.65c 44.56 cc 82.75 c
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38
8 Feedback requested
We seek your feedback on our assessment of options, application of the Investment
Test, and potential application to the Commerce Commission relating to this project.
We have asked a number of questions throughout this document. These are
summarised in the Appendix Section A.4. They are intended to aid your response.
You are not obliged to answer all or any of these questions and are welcome to raise
other issues which you believe might be relevant.
If you have questions during the consultation period you may email them to
[email protected] and we will attempt to answer them within one
week of receipt. If you could put “BPE-WIL consultation” in the subject line that would
be helpful.
We seek written feedback by 5pm on the 17th of April 2018. Responses should be in
electronic form, in either Microsoft Word or PDF format, and emailed to
Our intent is to publish all submissions and further information on Transpower’s
website, at https://www.transpower.co.nz/bunnythorpe-wilton-reconductoring-
investigation
If there is any aspect of your submission that is confidential, please:
• clearly mark the sections you consider confidential and indicate why
• indicate whether we can share the confidential information with the Commerce
Commission
Transparency is important in this process and we may not be able to rely on
confidential information to justify an investment proposal. Further, you should be
aware that both Transpower and the Commerce Commission are subject to the
provisions of the Official Information Act 1982.
We will acknowledge all submissions. Please note that late submissions may not be
considered.
Following consultation, we will consider feedback received in submissions. Based on
the information received, we will prepare an application to the Commerce Commission
to seek approval to increase our base capex funding baseline for RCP2 to account for
this work. Our intent, at this stage is to make this application in June 2018.
Thank you in advance for your assistance with this project.
8 Feedback requested
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A.1 Capex IM requirements
In the below table we outline how this proposal meets the requirements to be
approved by the Commerce Commission under the Capex IM.
Table 17 - Capex IM checklist
Capex IM section Report cross reference
2.2.3 Listed Project
(2) Listed project definition (a) (i) capex > $20 million
(ii) to be commissioned in the regulatory period (b) replacement/ refurbishment (c) commencement date within the regulatory period (d) not already in base capex
4.3 Costs
3.2.4 Approval of base capex in addition to the base capex allowance
(1) Due by June twenty-two months before the end of a regulatory period
Submission expected in June 2018 (due before Aug 2018)
(2)(a) reason for project, technical evidence 2.2 Need
(2)(b) options considered 3 Identify options
(2)(c) scope and grid outputs 2 Need verification and assessment level
(2)(d) technical and costing info & risks 4.3 Costs
(2)(e) costs by year and assumptions To be completed for final consultation
(2)(f) cost-benefit and sensitivity 4.5.4 Expected net electricity market benefit 4.5.5 Robustness of the results
(2)(g) consultation 6 Consultation to date A.3 September 2016 stakeholder consultation
(2)(h) Board and CEO sign-off To be completed for final consultation
(4)(a) consultation process as per base capex (publish / X-subs,etc) Appendix 3 (consultation responses)
(4)(b) evaluated as per base capex criteria, including Schedule A where relevant: - follow Transpower policies and planning standards for grid / base capex; - cost-effective; - reasonable assumptions (method); - risk-based good asset management, - grid output dependencies - deliverability; - reasonable asset replacement models (inputs & method); - reasonable demand forecasts (inputs & method); - scope for efficiency gains
2.2 Need 4.4 Economic assumptions
(5)(a) forecast CPI used for base capex in regulatory period; (b) forecast FX rates used for base capex for regulatory period; (c) percentage of foreign capex
To be completed for final consultation
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A.2 Short-listed conductors In the below table we summarise the reconductoring options that were considered in order to derive our short-list.
Conductor Meets load growth scenarios
Future upgrade possible and reasonable
Property rights infringement and environmental impacts
Engineering issues Preferred conductor for JFD-WIL section
Zebra duplex ACSR/AC (@65°C)
Yes Yes, but at unnecessary expense if de-rated now
Will maintain the status quo Straight forward delivery.
Zebra duplex ACSR/AC (@75°C)
Yes Yes Will maintain the status quo Straight forward delivery.
Goat duplex ACSR/AC (@94°C)
Yes No, may anneal and mechanically damage the conductor
Will maintain the status quo Reasonably straight forward delivery. Dissimilar conductor requires more attention during construction.
Selenium duplex AAAC (@70°C)
Yes No, clearance rectifications would not be reasonable
Exceeds existing conductor envelope, risk many property infringements. Some clearance rectifications may require consents.
Some under-clearances may not have feasible mitigations. Reasonably straight forward wiring, dissimilar conductor requires more attention during construction.
Sulphur duplex AAAC (@57°C)
Yes No, clearance rectifications would not be reasonable
Exceeds existing conductor envelope, risk of many property infringements not covered in cost assessment, many assessments to be undertaken
Some under-clearances and structure overloads may not have feasible mitigations. Reasonably straight forward wiring, dissimilar conductor requires more attention during construction.
Chukar simplex (with circuit reconfiguration) ACSR/AC (@65°C)
Yes Yes Will maintain the status quo. Consent and property rights required at JFD Tee site
Duplex --> Simplex requires more attention and management methods during construction. Substation works impose moderate programme dependencies and additional design work-streams (costs included).
✓
8 Feedback requested
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A.3 September 2016 stakeholder consultation: summary
of submissions with Transpower responses
This section summarises submissions received on our long-list consultation paper
Bunnythorpe to Wilton line (Judgeford to Wilton section) reconductoring of September 2016
(long-list consultation)16. Below we have endeavoured to summarise submitter’s key points
briefly: please refer to their submissions for further detail.
Submissions were received from:
• Major Electricity Users Group (MEUG)
• Contact Energy Limited
We include the submitters’ comments against the 11 specific questions asked in the
consultation report, plus any general comments of relevance to specific questions. We also
provide our response to each issue raised.
Our questions, and additional questions from submitters, are listed under the relevant
subject heading from the long-list consultation report.
A.3.1 Need and project scope
Q1 Are there any other considerations relating to the need that we should incorporate into this project?
MEUG responded that Transpower should incorporate an assessment of the exacerbators
and beneficiaries of the preferred solution and the incremental cost they will pay versus the
benefit they will receive.
Transpower response:
We have not estimated the cost that proposed changes to the Transmission Pricing Methodology might impose on specific customers.
Contact Question
Is the higher North Island price (identified as a result of the HAY-BPE constraints) considered in the option analysis, i.e. the option that would have the least construction time and therefore lower exposure to the pricing risk?
Transpower response:
The duration of construction has not been considered in our options assessment. However, we do not consider it material to our option assessment for this project. The preferred option requires less tower and foundation strengthening than the other reconductoring options considered. Also, after the Judgeford tee is commissioned at the beginning of the second year of work, generation constraints during most construction will be similar to the existing system with all circuits in service as the BPE-WIL circuit will be disconnected at the tee point (JFD). Therefore, outages on the JFD-WIL section will have little impact on HAY-
16 The consultation paper, the non-confidential submissions and this document are available at
https://www.transpower.co.nz/bunnythorpe-wilton-reconductoring-investigation
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BPE capacity. There will be some outages equivalent to taking HAY-LTN out of service in the present system to commission the double tee and complete the associated protection work.
Contact Question
If a decision to shut or reduce demand at Tiwai is made then would this project be expedited so that it occurs prior to this demand reduction occurring to minimise the pricing risk due to higher DC north flow?
Transpower response:
We intend to proceed with delivery as soon as we obtain regulatory approval, therefore there is not an opportunity to expedite commissioning of the project.
A.3.2 Long-list of options
Q2 Is our long-list of options reasonable? Should any other options be added to the list?
No responses received.
A.3.3 Non-transmission solution information
Q3 Do you have any suggestions or proposals for non-transmission solutions to meet the need? If so, please provide the information requested (in section 5.4) so that we can apply a high-level assessment against our short-listing criteria?
Contact has responded with a battery storage non-transmission solution to address the
reduction in security during construction. Further details of this solution can be found in
Contact’s submission on the project website16.
Contact Question
It is mentioned that a Non-Transmission Solution (NTS) is likely to be required during the construction phase to mitigate the risk of reduced security. What is the timeframe of this construction phase and scale of NTS required?
Transpower response:
There will be little or no reduction in security, so non-transmission solutions will not be required. We identified that there may be a role for non-transmission solutions to mitigate any potential reduction in security to Wellington during construction. However, we have now confirmed that the value of any such mitigation would be very low to zero.
A.3.4 Short-listing criteria
Q4 Do you agree with our criteria for short-listing? If not, which criteria should we modify, include or remove, and why?
MEUG agreed with the criteria for short-listing.
8 Feedback requested
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A.3.5 Peak demand assumptions
Q5 Are our demand forecast assumptions appropriate for this investigation? If not, please outline any significant (>5 MW) increases or decreases in load you expect to occur in the Wellington region.
MEUG is unsure whether the use of a one-size fits all P90 forecast is appropriate. They
suggest a lower percentile forecast in the near term where there are maintenance or other
options available allowing deferral of high cost decisions.
Transpower response:
This option assessment is based on expected (P50) forecasts and a range of market development scenarios. Transpower uses our prudent (P90) forecast to identify future needs that are driven by load growth to ensure that the needs are identified early. All economic assessments are undertaken using the expected forecast.
A.3.6 Market development scenarios
Q6 Are these market development scenarios appropriate for this investigation? If not, we welcome specific information regarding changes.
No responses received.
A.3.7 Analysis period
Q7 Do you consider the proposed calculation period of 40 years appropriate for the Bunnythorpe to Wilton A (Judgeford to Wilton Section) Line Reconductoring investigation?
MEUG responded “yes”, and also suggested to test a scenario with a 20-year horizon as
defined in the Capex IM.
A.3.8 Value of expected unserved energy
Q8 Do you consider this VoLL ($25,300/MWh) appropriate for valuing unserved energy?
MEUG responded that Transpower should consider the more recent analysis by the
Electricity Authority (Investigation into the Value to Lost Load in New Zealand – Report on
methodology and key findings, 23rd July 2013).
Transpower response:
We note the caveats included in the EA’s report regarding the applicably of the published VoLL figures to the general population. As such, we consider the report a valuable start to a comprehensive VoLL review, but insufficient justification to change the VoLL figures at this time. We have undertaken sensitivity analysis to ensure our results are not sensitive to this figure.
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Q9 Do you consider this VoLL appropriate for valuing lost load for your business? If, not, what alternative VoLL would you recommend and what evidence are you able to provide to support your recommendation?
MEUG responded that Transpower should consider the more recent analysis by the
Electricity Authority (Investigation into the Value to Lost Load in New Zealand – Report on
methodology and key findings, 23rd July 2013).
Transpower response:
See our comments above.
A.3.9 Discount rate
Q10 Do you consider a discount rate of 7% appropriate for this investigation?
MEUG pointed to the Capex IM review in 2017 which might specify the discount rate to be
applied.
Transpower
response:
Transpower will adopt the discount rate as suggested by the Capex IM.
A.3.10 Expected Net Electricity Market Benefit
Q11 Are there other market costs or benefits which should be reflected in the analysis?
No responses were received.
8 Feedback requested
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A.4 Consultation questions in this document
Question 3: Do you have any comments on our analysis of costs and
benefits for this project?
Question 4: Do you agree with our assessment of the preferred solution and
our application of the Investment Test?
Question 2: Do you agree with our assessment of the long-list?
Question 5: What would you consider a material change in cost?
Question 1: Are there any other considerations relating to the need that we
should incorporate into this project?